Terms of Use

ACCESSING THIS SITE SIGNIFIES YOUR AGREEMENT TO THE TERMS AND CONDITIONS OF USE. PLEASE READ THESE TERMS CAREFULLY BEFORE USING THIS SITE.

Cautionary Note to U.S. Investors - The information contained in this website is provided solely for convenience. The documents contained herein are historical in nature. Therefore, events following the date of publication or subsequently available information may have rendered obsolete the estimates, assertions or other information contained in these documents. All information is provided without warranty of any kind. Marathon Oil assumes no duty to update the information contained in any of the documents and further assumes no responsibility for the accuracy of the information. Marathon Oil further reserves the right to change the content of the site at any time without notice.

Any person who uses, or makes decisions upon, information contained in this website does so at their own risk and agrees to hold Marathon Oil Corporation and its subsidiaries and affiliates harmless. Marathon Oil Corporation and its employees and representatives further expressly disclaim all liability for any costs, expenses, damages or consequences of any type that may result from reliance on the information obtained from this website or any website linked hereto.

The United States Securities and Exchange Commission (the "SEC") permits oil and gas companies, in their filings with the SEC, to disclose only proved probable and possible reserves. From time to time, we may use certain terms on this website or the documents contained herein, such as net unrisked mean resource potential, net unrisked resource potential, net resource, 2P resource, 2P net resource, net 2P resource, gross unrisked potential resource, gross resources, gross discovered resources, gross resource potential, gross block resource potential, resources, resource potential, potential resource, and other similar terms or variations of the foregoing terms. The SEC guidelines strictly prohibit us from including these terms in filings with the SEC. U.S. Investors are urged to consider closely the disclosures in our Forms 10-K, 10-Qs and 8-Ks, Commission File No. 1-5153, available from us at Marathon Oil Corporation, Attn. Investor Relations, 5555 San Felipe Street, Houston, TX 77056-2723. Our Form 10-K and other filings with the SEC can also be electronically accessed from our website or the SEC's website at http://www.sec.gov/.

MRO-2014.12.31-10K


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2014
Commission file number 1-5153
Marathon Oil Corporation
(Exact name of registrant as specified in its charter)
 
Delaware
 
25-0996816
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
5555 San Felipe Street, Houston, TX 77056-2723
(Address of principal executive offices)
(713) 629-6600
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
 
Title of each class
 
Name of each exchange on which registered
Common Stock, par value $1.00
 
New York Stock Exchange
 Securities registered pursuant to Section 12(g) of the Act: None
  

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes R No £
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes  £ No  R
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.  Yes R No £
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes R No £
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  R
Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer  R    Accelerated filer  £ Non-accelerated filer  £ Smaller reporting company  £
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  £ No   R
The aggregate market value of Common Stock held by non-affiliates as of June 30, 2014: $26,831 million. This amount is based on the closing price of the registrant’s Common Stock on the New York Stock Exchange on that date. Shares of Common Stock held by executive officers and directors of the registrant are not included in the computation. The registrant, solely for the purpose of this required presentation, has deemed its directors and executive officers to be affiliates.
There were 674,944,619 shares of Marathon Oil Corporation Common Stock outstanding as of February 23, 2015.
Documents Incorporated By Reference:
Portions of the registrant’s proxy statement relating to its 2015 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934, are incorporated by reference to the extent set forth in Part III, Items 10-14 of this report.





MARATHON OIL CORPORATION
Unless the context otherwise indicates, references to "Marathon Oil," "we," "our" or "us" in this Annual Report on Form 10-K are references to Marathon Oil Corporation, including its wholly-owned and majority-owned subsidiaries, and its ownership interests in equity method investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon Oil exerts significant influence by virtue of its ownership interest).
Table of Contents
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



Definitions
Throughout this report, the following company or industry specific terms and abbreviations are used.
AECO – Alberta Energy Company, a Canadian natural gas benchmark price.
AMPCO – Atlantic Methanol Production Company LLC, a company located in Equatorial Guinea in which we own a 45 percent equity interest.
AOSP – Athabasca Oil Sands Project, an oil sands mining, transportation and upgrading joint venture located in Alberta, Canada, in which we hold a 20 percent non-operated working interest.
bbl – One stock tank barrel, which is 42 United States gallons liquid volume.
bbld – Barrels per day.
bboe – Billion barrels of oil equivalent. Natural gas is converted to a barrel of oil equivalent based on the energy equivalent, which on a dry gas basis is six thousand cubic feet of gas per one barrel of oil equivalent.
bcf – Billion cubic feet.
boe – Barrels of oil equivalent.
boed – Barrels of oil equivalent per day.
btu – British thermal unit, an energy equivalence measure.
Budget – Our capital, investment and exploration spending budget as made public through a press release.
DD&A – Depreciation, depletion and amortization.
Developed acreage – The number of acres which are allocated or assignable to producing wells or wells capable of production.
Development well – A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Downstream business – The refining, marketing and transportation ("RM&T") operations, spun-off on June 30, 2011 and treated as discontinued operations.
Dry well – A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion.
E.G. – Equatorial Guinea.
EGHoldings – Equatorial Guinea LNG Holdings Limited, a liquefied natural gas production company located in E.G. in which we own a 60 percent equity interest.
EIA – United States Energy Information Agency.
EPA – United States Environmental Protection Agency.
Exploratory well – A well drilled to find oil or natural gas in an unproved area or find a new reservoir in a field previously found to be productive in another reservoir.
FASB – Financial Accounting Standards Board.
FPSO - Floating production, storage and offloading vessel.
IFRS – International Financial Reporting Standards.
Internal Losses  Production losses attributed to factors that are within our control which can be either planned, such as a planned turnaround, or unplanned, such as equipment failure.
International E&P – Our International Exploration and Production ("Int'l E&P") segment which explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured from natural gas, such as liquefied natural gas and methanol, in E.G.
IRS – United States Internal Revenue Service.
KRG – Kurdistan Regional Government.
Light sweet crude - A crude oil with an American Petroleum Institute ("API") gravity of 38 degrees or more and a sulfur content of less than 0.5 percent.
LNG – Liquefied natural gas.

1


LPG – Liquefied petroleum gas.
Liquid hydrocarbons or liquids – Collectively, crude oil, synthetic crude oil, condensate and natural gas liquids.
LLS – Louisiana Light Sweet crude oil, an oil index benchmark price.
Marathon – The consolidated company prior to the June 30, 2011 spin-off of the downstream business.
Marathon Oil – Marathon Oil Corporation and its consolidated subsidiaries: the company as it exists following the June 30, 2011 spin-off of the downstream business.
Marathon Petroleum Corporation ("MPC") – The separate independent company which now owns and operates the downstream business.
mbbl – Thousand barrels.
mbbld – Thousand barrels per day.
mboe – Thousand barrels of oil equivalent.
mboed – Thousand barrels of oil equivalent per day.
mcf – Thousand cubic feet.
mmbbl – Million barrels.
mmboe – Million barrels of oil equivalent.
mmbtu – Million British thermal units.
mmcfd – Million cubic feet per day.
mmt – Million metric tonnes.
mmta – Million metric tonnes per annum.
mtd – Thousand metric tonnes per day.
Net acres or Net wells – The sum of the fractional working interests owned by us in gross acres or gross wells.
NGL or NGLs – Natural gas liquid or natural gas liquids, which are naturally occurring substances found in natural gas, including ethane, butane, isobutane, propane and natural gasoline, that can be collectively removed from produced natural gas, separated into these substances and sold.
North America E&P – Our North America Exploration and Production segment ("N.A. E&P") which explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America.
OCI – Other comprehensive income.
OECD – Organization for Economic Cooperation and Development.
OPEC – Organization of Petroleum Exporting Countries.
Operational availability A term used to measure the ability of an asset to produce to its maximum capacity over a specified period of time, after consideration of Internal Losses.
OSM – Our Oil Sands Mining segment which mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
Productive well – A well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.
Proved developed reserves – Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or for which the cost of the required equipment is relatively minor compared to the cost of a new well and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved reserves – Proved crude oil and condensate, NGLs, natural gas and synthetic crude oil reserves are those quantities of crude oil and condensate, NGLs, natural gas and synthetic crude oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether

2


deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Proved undeveloped reserves – Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion or through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
PSC – Production sharing contract.
Quest CCS – Quest Carbon Capture and Storage project at the AOSP in Alberta, Canada.
Reserve replacement ratio – A ratio which measures the amount of proved reserves added to our reserve base during the year relative to the amount of liquid hydrocarbons and natural gas produced.
Royalty interest – An interest in an oil or natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.
SAGE – United Kingdom Scottish Area Gas Evacuation system composed of a pipeline and processing terminal.
SAR or SARs – Stock appreciation right or stock appreciation rights.
SCOOP – South Central Oklahoma Oil Province.
SEC – United States Securities and Exchange Commission.
Seismic – An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formation (3-D seismic provides three-dimensional pictures and 4-D factors in changes that occurred over time).
STACK – Sooner Trend, Anadarko (basin), Canadian (and) Kingfisher (counties).
Total depth ("TD") – The bottom of a drilled hole.
Total proved reserves – The summation of proved developed reserves and proved undeveloped reserves.
U.K. – United Kingdom.
Undeveloped acreage – Acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
U.S. – United States of America.
U.S. GAAP – Accounting principles generally accepted in the U.S.
WCS – Western Canadian Select, an oil index benchmark price.
Working interest ("WI") – The interest in a mineral property which gives the owner that share of production from the property. A working interest owner bears that share of the costs of exploration, development and production in return for a share of production. Working interests are sometimes burdened by overriding royalty interest or other interests.
WTI – West Texas Intermediate crude oil, an oil index benchmark price.


3


Disclosures Regarding Forward-Looking Statements
This Annual Report on Form 10-K, including Item 1. Business, Item 1A. Risk Factors, Item 3. Legal Proceedings, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures About Market Risk, contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical fact included or incorporated by reference in this report are forward-looking statements, including without limitation statements regarding: our operational, financial and growth strategies, ability to successfully effect those strategies and the expected results therefrom; our 2015 capital, investment and exploration budget and the planned allocation thereof; planned capital expenditures and the impact thereof; planned activities, including drilling plans and projects, planned wells, rig count, inventory, seismic, exploration plans and maintenance activities, and the expected timing and impact thereof; expectations regarding future economic and market conditions and the effects on us thereof; our financial and operational outlook, and ability to fulfill that outlook; our financial position, balance sheet, liquidity and capital resources, and the benefits thereof; resource and asset quality and the expected benefits and performance thereof; reserve estimates and growth expectations; future production and sales expectations, and the drivers thereof; and statements related to enhanced completion designs, downspacing, co-development, high-density pilots, and the expected benefits and results thereof. In addition, many forward-looking statements may be identified by the use of forward-looking terminology such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. While we believe that our assumptions concerning future events are reasonable, we can give no assurance that these expectations will prove to be correct. A number of factors could cause results to differ materially from those indicated by such forward-looking statements including, but not limited to:
conditions in the oil and gas industry, including the level of supply or demand for crude oil and condensate, NGLs, natural gas and synthetic crude oil and the impact on the price of crude oil and condensate, NGLs, natural gas and synthetic crude oil;
changes in political or economic conditions in key operating markets, including international markets;
the amount of capital available for exploration and development;
timing of commencing production from new wells;
drilling rig availability;
availability of materials and labor;
the inability to obtain or delay in obtaining necessary government or third-party approvals and permits;
non-performance by third parties of their contractual obligations;
unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto;
cyber-attacks adversely affecting our operations;
changes in safety, health, environmental and other regulations;
other geological, operating and economic considerations; and
other factors discussed in Item 1. Business, Item 1A. Risk Factors, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and elsewhere in this report.
All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we assume no duty to revise or update any forward-looking statements whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.




4


PART I
Item 1. Business
General
Marathon Oil Corporation is a global energy company based in Houston, Texas, with operations in North America, Europe and Africa. Our corporate headquarters are located at 5555 San Felipe Street, Houston, Texas 77056-2723 and our telephone number is (713) 629-6600. Each of our three reportable operating segments is organized based upon both geographic location and the nature of the products and services it offers.
North America E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas in North America;
International E&P – explores for, produces and markets crude oil and condensate, NGLs and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and
Oil Sands Mining – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.
  We were incorporated in 2001. On June 30, 2011, we completed the spin-off of our downstream business, creating two independent energy companies: Marathon Oil and MPC.
Strategy and Results Summary
We have production operations in the U.S., E.G., Canada, the U.K. and Libya. The focus of our U.S. operations is our three core unconventional resource plays: the Eagle Ford, Bakken and Oklahoma Resource Basins. Our exploration prospects are in E.G., Ethiopia, Gabon, Kenya, the Kurdistan Region of Iraq and the U.S, primarily in the Gulf of Mexico. Our strategy is guided by the following seven strategic imperatives ("SI7"):
1.Living Our Values
2.
Investing in Our People
3.
Continuous Improvement in Operational and Capital Efficiency
4.
Driving Profitable and Sustainable Growth
5.
Rigorous Portfolio Management
6.
Quality and Material Resource Capture
7.
Delivering Long-Term Shareholder Value
In 2014, we continued to focus on liquid hydrocarbon reserves, realizing substantial increases in our three unconventional resource plays, the Eagle Ford, Bakken and Oklahoma Resource Basins. In 2014, our U.S. operations added 288 mmboe proved reserves, excluding acquisitions, dispositions and production, amounting to an increase of 37 percent over the prior year's ending balance.
For the total company, we ended 2014 with proved reserves of approximately 2,198 mmboe, compared to 2,171 mmboe at the end of 2013. Excluding proved reserves of 106 mmboe related to our Angola and Norway discontinued operations, proved reserves related to continuing operations increased from 2,065 mmboe at the end of 2013 to 2,198 mmboe at the end of 2014 for an increase of 6 percent.
We continually evaluate ways to optimize our portfolio through acquisitions and divestitures. In 2014, we executed two strategic dispositions for aggregate cash proceeds of more than $4 billion. We closed the sale of our Angola assets in the first quarter and our Norway business in the fourth quarter.
During 2014, we repurchased approximately 29 million shares for $1 billion. Our cash additions to property, plant and equipment related to continuing operations were $5.2 billion, primarily funded with cash flow from operations, with more than 70 percent of that related to our Eagle Ford, Bakken and Oklahoma Resource Basins where net sales volumes increased 35 percent year-over-year.

5


See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Outlook, for discussion of our 2015 Budget.
The map below shows the locations of our worldwide operations.
Segment and Geographic Information
For operating segment and geographic financial information, see Item 8. Financial Statements and Supplementary Data – Note 7 to the consolidated financial statements.
In the following discussion regarding our North America E&P, International E&P and Oil Sands Mining segments, references to net wells, acres, sales or investment indicate our ownership interest or share, as the context requires.
North America E&P Segment
We are engaged in oil and gas exploration, development and/or production activities in the U.S. and Canada.
Unconventional Resource Plays
Eagle Ford - As of December 31, 2014, we had approximately 180,000 net acres in the Eagle Ford in south Texas and 954 gross (714 net) operated producing wells, where we have been operating since 2011. During 2014, we reached total depth on 360 gross operated wells and brought 310 gross operated wells to sales, compared to 299 reaching total depth and 307 brought to sales in 2013. Included with the Eagle Ford well counts noted above, were 22 gross operated Austin Chalk wells brought online in 2014 and the first four Upper Eagle Ford wells which were brought online late in the fourth quarter of 2014. Our 2014 average spud-to-TD time was 13 days compared to 12 days in 2013. Our high-density pad drilling continues to average approximately four wells per pad in 2014. This higher pad density and the longer laterals being drilled in 2014 contribute to the slightly higher spud-to-TD time in 2014.
Throughout 2013, we evaluated the potential of downspacing to 40-acre and 60-acre spacing with several pilot programs. Wells drilled in these programs at closer spacing showed improved completion efficiency which helped offset impacts due to tighter well spacing. The continued focus on stimulation design has contributed to incremental improvements in well performance across our area of activity.
Eagle Ford net sales in 2014 were 112 mboed, 65 percent crude oil and condensate, 17 percent NGLs and 18 percent natural gas, compared to 81 mboed in 2013, a 38 percent increase. In 2014, we transported approximately 70 percent of our

6


Eagle Ford production by pipeline and anticipate this to increase to 90 percent in 2015 as additional pipeline capacity is constructed and completed. The ability to transport more barrels by pipeline enables us to improve/optimize price realizations, reduce costs, improve reliability and lessen our environmental footprint.
During 2014, we continued evaluation of the Austin Chalk formation across our Eagle Ford acreage position in south Texas, delineating 18,000 initial Austin Chalk acres and bringing online 22 wells. Initial Austin Chalk production results indicate that the mix of crude oil and condensate, NGLs and natural gas is similar to Eagle Ford condensate wells. We plan to drill 56 to 62 additional gross wells in the Austin Chalk formation in 2015. Co-development of the Austin Chalk and Lower Eagle Ford will leverage the infrastructure investments we have made to support production growth across the Eagle Ford operating area. During the fourth quarter of 2014, the first four Upper Eagle Ford wells were brought online and we spud our first four-well pilot with Austin Chalk, Upper Eagle Ford, and two Lower Eagle Ford wells.
We operate approximately 800 miles of gathering pipeline in the Eagle Ford area. We now have 31 central gathering and treating facilities, with aggregate capacity of more than 460 mboed. We also own and operate the Sugarloaf gathering system, a 37-mile natural gas pipeline through the heart of our acreage in Karnes, Atascosa, and Bee Counties of south Texas.
Approximately 40 percent of our 2015 Budget, $1.4 billion, is allocated to the Eagle Ford. Our drilling plans for 2015 include drilling 141 - 152 net wells (245 - 260 gross, of which we will operate 215 - 225), a decrease of approximately 40 percent over 2014. We anticipate bringing 255 - 275 gross operated wells to sales during 2015.
Bakken – We hold approximately 290,000 net acres in the Bakken shale oil play in North Dakota and eastern Montana, where we have been operating since 2006. Since inception, we have continuously sought improvement in efficiency and well performance through optimizing completion techniques. We began high-density spacing pilots in 2014, with each pad comprised of six Middle Bakken formation and six Three Forks first bench formation wells per drilling-spacing unit. We continue to execute an enhanced completion design pilot program, including elevated proppant volumes, hybrid slickwater fracs, increased stages and cemented liners, with 42 of the 55 tests online at the end of 2014.
Our time to drill a well averaged 17 days spud-to-TD in 2014 compared to 15 days in 2013. We reached TD on 83 gross operated wells and brought to sales 67 gross operated wells in 2014 compared to 76 reaching total depth and 77 brought to sales in 2013.  We recompleted 35 wells during 2014.
Our net sales from the Bakken shale averaged 51 mboed in 2014, approximately 88 percent crude oil, 6 percent NGLs and 6 percent natural gas, compared to 39 mboed in 2013, a 31 percent increase. In efforts to optimize price realizations, we sell our production in local North Dakota markets and to select purchasers who may elect to transport outside the state.
Approximately 20 percent of our 2015 Budget, $760 million, is allocated to the Bakken. Our 2015 Bakken program includes plans to drill 42 - 53 net wells (100 - 120 gross, of which we will operate 38 - 48). We anticipate bringing 68 - 78 gross operated wells to sales during 2015.
Oklahoma Resource Basins – Our primary focus in 2015 will be in the SCOOP and STACK areas.  In the SCOOP area we hold approximately 145,000 net acres with rights to the unconventional Woodford, Springer, Granite Wash and other Pennsylvanian sands plays.  We also hold approximately 100,000 net acres in the STACK area with rights to the unconventional Woodford, Meramec and other Mississippian plays.  These totals include over 50,000 acres added in the SCOOP and STACK areas in 2014.  Though not a focus of the 2015 program, we also hold 57,000 net acres in the broader western Oklahoma Granite Wash and other Pennsylvanian sands plays.  
In the SCOOP and STACK areas, we reached total depth on 17 gross operated wells and brought 18 gross operated wells to sales in 2014 compared to 10 reaching total depth and nine brought to sales in 2013. A total of nine net non-operated unconventional wells were brought to sales in 2014 compared to three in 2013.
Sales from our Oklahoma Resource Basins in 2014 were primarily from the Anadarko Woodford shale and averaged 18 mboed, approximately 16 percent crude oil, 28 percent NGLs and 56 percent natural gas, compared to 14 mboed in 2013, a 29 percent increase.
Approximately 6 percent of our 2015 Budget, $226 million, is allocated to the Oklahoma Resource Basins.  Our drilling plans for the Oklahoma Resource Basins in 2015 include drilling and completing 17 - 20 net wells (41 - 50 gross of which 16 - 20 are company operated wells).  We anticipate bringing 18 - 22 gross operated wells to sales during 2015.
See below for discussion of our conventional, primarily natural gas, production operations in Oklahoma.

7


Other United States
Gulf of MexicoProduction – On December 31, 2014, we held significant interests in 11 producing fields, four of which are company-operated. Average net sales in 2014 from the Gulf of Mexico were 14 mbbld of liquid hydrocarbons and 16 mmcfd of natural gas, or 17 mboed compared to 19 mboed in 2013. Operational availability for our operated properties was 96 percent, with internal unplanned losses of four percent.
We have a 65 percent operated working interest in the Ewing Bank Block 873 platform which is located 130 miles south of New Orleans, Louisiana. The platform serves as a production hub for the Lobster, Oyster and Arnold fields on Ewing Bank Blocks 873, 917 and 963. The facility also processes third-party production via subsea tie-backs.
We have a 50 percent non-operated working interest in the Petronius field on Viosca Knoll Blocks 786 and 830, located 130 miles southeast of New Orleans, which includes 15 producing wells. The Petronius platform is also capable of providing processing and transportation services to nearby third-party fields.
We hold a 30 percent non-operated working interest in the Neptune field located on Atwater Valley Block 575, 120 miles south off the coast of Louisiana. The development includes seven subsea wells tied back to a stand-alone platform. A new Neptune sidetrack well came online late December 2014.
We have an 18 percent non-operated working interest in the Gunflint field development located on Mississippi Canyon Blocks 948, 949, 992(N/2) and 993(N/2), 90 miles south off the coast of Louisiana. The discovery well was drilled in 2008 and encountered pay in the Middle Miocene reservoirs. Two subsequent appraisal wells were drilled and evaluated in 2012 and 2013. The subsea tie-back development project will continue to progress in 2015, with first oil expected in 2016.
Gulf of Mexico – ExplorationWe have a 3-year shared contract on the Maersk Valiant drillship and plan to utilize the rig to test prospects in the Gulf of Mexico, including one operated exploration well in 2015.  As we evaluate various opportunities for drilling, we may seek partners to further reduce our exploration risk on individual projects.
A deepwater oil discovery on the Shenandoah prospect, located on Walker Ridge Block 52, was drilled in 2009. We own a 10 percent non-operated working interest in this prospect. The first appraisal well on the Shenandoah prospect reached total depth in 2013 and was successful. The second appraisal well was spud in late May 2014 and the well costs incurred through December 31, 2014 were expensed in the fourth quarter of 2014. A third appraisal well is anticipated to spud on Walker Ridge Block 51 in 2015.
In the fourth quarter of 2014, we drilled two exploratory wells in the Gulf of Mexico: one on the Key Largo prospect, located on Walker Ridge Block 578, in which we have a 60 percent working interest and one on the Perseus prospect, located on Desoto Canyon Block, in which we have a 30 percent non-operated working interest. Neither well encountered commercial hydrocarbons and the well costs incurred through December 31, 2014 were charged to dry well expense. We have no further plans to explore either prospect.
Oklahoma – We have long-established operated and non-operated conventional production in several Oklahoma fields from which sales averaged 8 mboed in 2014 and 9 mboed in 2013.
Texas/North Louisiana/New Mexico – We hold approximately 242,000 net acres in these areas of which approximately 20,000 of the acres are in the Haynesville and Bossier natural gas shale plays. Most of the acreage in these shale plays is held by production. We participated in one gross non-operated well in the Haynesville shale play during 2014. Conventional production was primarily from the Mimms Creek, Pearwood and Haynesville fields in 2014, with net sales averaging 5 mboed in both 2014 and 2013. We also participate in several non-operated Permian Basin fields in west Texas and New Mexico. Net sales from this area averaged 7 mboed in 2014.
Wyoming – We have ongoing enhanced oil recovery waterflood projects at the mature Bighorn Basin and Wind River Basin fields and at our 100 percent owned and operated Pitchfork field. We have conventional natural gas operations in the Greater Green River Basin. Operated production at the Powder River Basin field ceased in March 2014, and plug and abandonment activities were substantially complete as of December 31, 2014.
Our Wyoming net sales averaged 16 mbbld of liquid hydrocarbons and 11 mmcfd of natural gas, or 18 mboed, during 2014 compared to 22 mboed in 2013. We drilled 11 gross operated development wells in Wyoming in 2014. In addition, we own and operate the 420-mile Red Butte Pipeline. This crude oil pipeline connects Silvertip Station on the Montana/Wyoming state line to Casper, Wyoming.

8


Canada
We hold interests in both operated and non-operated exploration stage oil sand leases in Alberta, Canada, which would be developed using in-situ methods of extraction. These leases cover approximately142,000 gross (54,000 net) acres in four project areas: Namur, in which we hold a 70 percent operated interest; Birchwood, in which we hold a 100 percent operated interest; Ells River, in which we hold a 20 percent non-operated interest; and Saleski in which we hold a 33 percent non-operated interest.
During 2012, we submitted a regulatory application relating to our Canada in-situ assets at Birchwood, for a proposed 12 mbbld steam assisted gravity drainage ("SAGD") demonstration project. We expect to receive regulatory approval for this project by the end of 2015.  Upon receiving this approval, we will further evaluate our development plans.
North America E&P--Acquisitions
In an asset acquisition that closed August 2014, we added acreage to our Oklahoma Resource Basins at a cost of approximately $80 million before final settlement adjustments.
In the fourth quarter of 2014, we acquired additional acreage in the SCOOP, at a cost of approximately $60 million before final settlement adjustments.
International E&P Segment
We are engaged in oil and gas exploration, development and/or production activities in E.G., Ethiopia, Gabon, Kenya, the Kurdistan Region of Iraq, Libya and the U.K. We include the results of our natural gas liquefaction operations and methanol production operations in E.G. in our International E&P segment.
Africa
Equatorial GuineaProduction – We own a 63 percent operated working interest under a PSC in the Alba field which is offshore E.G. During 2014, E.G. net liquid hydrocarbon sales averaged 31 mbbld and net natural gas sales averaged 439 mmcfd, or 104 mboed, compared to 107 mboed in 2013. Operational availability from our company-operated facilities averaged approximately 98 percent in 2014, with internal unplanned losses of one percent. A compression project designed to maintain the production plateau two additional years and extend field life up to eight years is underway and is expected to be operational in 2016.
Dry natural gas from the Alba field, which remains after the condensate and LPG are removed by Alba Plant LLC, as discussed below, is supplied to AMPCO and EGHoldings under long-term contracts at fixed prices. Because of the location and limited local demand for natural gas in E.G., we consider the prices under the contracts with Alba Plant LLC, EGHoldings and AMPCO to be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or similar circumstances. Any dry gas not sold is returned offshore and reinjected into the Alba field for later production.
Equatorial GuineaExploration – We hold a 63 percent operated working interest in the Deep Luba discovery on the Alba Block and an 80 percent operated working interest in the Corona well on Block D. We plan to develop Block D through a unitization with the Alba field, which is currently being negotiated. We also have an 80 percent operated working interest in exploratory Block A-12 offshore Bioko Island, located immediately west of our operated Alba Field. The Sodalita West #1 exploratory well was spud during 2014 and reached total depth in February 2015. This well did not encounter commercial hydrocarbons and well costs incurred through December 31, 2014 were charged to dry well expense in the fourth quarter of 2014. A second exploratory well and one Alba field infill well are expected to be drilled in 2015.
Equatorial GuineaGas Processing – We own a 52 percent interest in Alba Plant LLC, an equity method investee, that operates an onshore LPG processing plant located on Bioko Island. Alba field natural gas is processed by the LPG plant. Under a long-term contract at a fixed price per btu, the LPG plant extracts secondary condensate and LPG from the natural gas stream and uses some of the remaining dry natural gas in its operations. During 2014, the gross quantity of natural gas supplied to the LPG production facility was 856 mmcfd, from which 6 mbbld of secondary condensate and 19 mbbld of LPG were produced by Alba Plant LLC.
We also own 60 percent of EGHoldings and 45 percent of AMPCO, both of which are accounted for as equity method investments. EGHoldings operates an LNG production facility and AMPCO operates a methanol plant, both located on Bioko Island. These facilities allow us to monetize natural gas reserves from the Alba field.
EGHoldings' 3.7 mmta LNG production facility sells LNG under a 3.4 mmta, or 460 mmcfd, sales and purchase agreement through 2023. The purchaser under the agreement takes delivery of the LNG on Bioko Island, with pricing linked principally to the Henry Hub index. Gross sales of LNG from this production facility totaled 4 mmta in 2014. Operational availability was 98 percent in 2014, including a planned turnaround, while internal unplanned losses were less than one percent.

9


AMPCO had gross sales totaling 885 mt in 2014. Operational availability for this methanol plant was 90 percent in 2014, and internal unplanned losses were ten percent. Production from the plant is used to supply customers in Europe and the U.S.
 Libya – We hold a 16 percent non-operated working interest in the Waha concessions, which encompass almost 13 million gross acres located in the Sirte Basin of eastern Libya.  Beginning in the third quarter of 2013, our Libya operations were impacted by third-party labor strikes at the Es Sider oil terminal. In early July 2014, Libya's National Oil Corporation rescinded force majeure associated with the third-party labor strikes, and our concession term was extended for slightly more than one year.  Although we had five liftings during 2014, in December 2014, Libya’s National Oil Corporation once again declared force majeure at Es Sider as disruptions from civil unrest continue. Considerable uncertainty remains around the timing of future production and sales levels. We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya.  See Item 8. Financial Statements and Supplementary Data – Note 12 to the consolidated financial statements for additional information about our Libya operations.
GabonExploration – We hold a 21.25 percent non-operated working interest in the Diaba License G4-223 and its related permit offshore Gabon, which covers approximately 2.2 million gross (477,000 net) acres. The Diaman-1B well reached total depth in the third quarter of 2013, encountering 160-180 net feet of hydrocarbon pay in the deepwater pre-salt play. Analysis confirmed dry gas accumulation with minor condensate. Multiple additional pre-salt prospects have been identified on this License. In 2014, 3D seismic acquisition was completed in the western part of the block.
In August 2014, we signed an exploration and production sharing contract for Gabon offshore Block G13, which was subsequently re-named Tchicuate. The block, which is located in the pre-salt play offshore Gabon, encompasses 277,000 acres. The seismic program is expected to be completed in the second quarter of 2015, and processing will occur through the remainder of the year. We hold a 100 percent participating interest and operatorship in the block. In the event of development, the Republic of Gabon will assume a 20 percent financed interest in the contract upon commencement of production. The State holds additional rights to participate in the block in the future as a co-investor.
KenyaExploration – We hold a 50 percent non-operated working interest in Block 9, consisting of approximately 3.9 million gross (1.9 million net) acres in northwest Kenya. The Sala-1 exploration well was spud in February 2014 on the eastern side of Block 9 and made a natural gas discovery in the second quarter of 2014. The well was drilled to a total depth of approximately 10,000 feet, and analysis indicated three zones of interest over a 3,280-foot gross interval which were subsequently drill-stem tested. The Sala-2 appraisal well spud in the third quarter of 2014, but did not encounter commercial hydrocarbons, and the well costs were charged to dry well expense. We hold a 50 percent non-operated working interest in Block 9 with the option to operate any commercial development.
We also hold a 15 percent non-operated working interest in Block 12A, covering approximately 3.8 million gross (566,000 net) acres, which is also located in northwest Kenya. The acquisition of 2D seismic on Block 12A began in 2013 and was completed in 2014. Multiple prospects have been identified and the first exploratory well is anticipated to be drilled in late 2015.
EthiopiaExploration – We hold a 20 percent non-operated working interest in the onshore South Omo Block in Ethiopia. The concession has an area of approximately 5.4 million gross (1.1 million net) acres. Two wells were drilled on the South Omo Block in 2014: the Shimela-1 well, which reached total depth in May 2014, and the Gardim-1 well, which reached total depth in July 2014. Neither well encountered commercial hydrocarbons and the well costs were charged to dry well expense during 2014.
We have a 50 percent non-operated working interest in the Rift Basin Area Block with approximately 10.5 million gross acres. We began 2D seismic acquisition in the first quarter of 2015 in order to develop prospect inventory for a future drilling program. We have the option to operate if a discovery is made.
Other – An outbreak of the Ebola virus has existed in certain regions of West Africa (Guinea, Liberia, Sierra Leone) since late 2013.  Although neither E.G. nor any other African country in which we have business activities has been impacted by Ebola to date, our business operations may be adversely affected through travel or other restrictions. We continue to monitor the situation, have enhanced our emergency response plans to address any potential impact, and are working closely with appropriate external parties to maintain business continuity and the health and well-being of our staff.
Other International
United Kingdom – Net sales from the U.K. averaged 11 mbbld of liquid hydrocarbons and 28 mmcfd of natural gas, or 16 mboed, in 2014 compared to 20 mboed in 2013. Our largest asset in the U.K. sector of the North Sea is the Brae area complex where we are the operator and have a 42 percent working interest in the South, Central, North and West Brae fields and a 39 percent working interest in the East Brae field. The Brae Alpha platform and facilities host the South, Central and West Brae fields. The North Brae and East Brae fields are natural gas condensate fields which are produced via the Brae Bravo and the East Brae platforms, respectively. The East Brae platform also hosts the nearby Braemar field in which we have a 28 percent

10


working interest. Operational availability in 2014 for the Brae complex was 90 percent and internal unplanned losses were nine percent. We brought two South Brae infill wells online late in the second half of 2014 and plan to complete two West Brae subsea wells and one additional South Brae infill well in 2015.
The strategic location of the Brae platforms, along with pipeline and onshore infrastructure, has generated third-party processing and transportation business since 1986. Currently, the operators of 31 third-party fields are contracted to use the Brae system and 72 mboed are being processed or transported through the Brae infrastructure. In addition to generating processing and pipeline tariff revenue, this third-party business optimizes infrastructure usage.
The working interest owners of the Brae area producing assets collectively own a 50 percent non-operated interest in the SAGE system. The SAGE pipeline transports natural gas from the Brae area, and the third-party Beryl area, and has a total wet natural gas capacity of 1.1 bcf per day. The SAGE terminal at St. Fergus in northeast Scotland processes natural gas from the SAGE pipeline as well as approximately 1 bcf per day of third-party natural gas.
We own non-operated working interests in the Foinaven area complex, consisting of a 28 percent working interest in the main Foinaven field, a 47 percent working interest in East Foinaven and a 20 percent working interest in the T35 and T25 fields. The export of Foinaven liquid hydrocarbons is via shuttle tanker from an FPSO to market. All natural gas sales are to the non-operated Magnus platform for use as injection gas.
Croatia – We were awarded, as part of a consortium, seven blocks located offshore in the Adriatic Sea, subject to negotiation of a PSC with the Croatian Government. We have a 60 percent interest in the consortium.
Kurdistan Region of Iraq – In aggregate, we have approximately 109,000 net acres in the Kurdistan Region of Iraq. We have a 45 percent operated working interest in the Harir block located northeast of Erbil. For a short time in 2014, we suspended certain operations due to security concerns in the region and continue to closely monitor the situation. We also have non-operated interests in two blocks located north-northwest of Erbil: Atrush with 15 percent working interest and Sarsang with 20 percent working interest.
On the non-operated Atrush block, following the successful appraisal program and a declaration of commerciality, the Kurdistan Ministry of Natural Resources approved a plan for field development in September 2013.  The development project consists of drilling three production wells and constructing a central processing facility in Phase 1 which provides for a 25-year production period. We expect first production in late 2015 with estimated initial gross production of approximately 30 mbbld of oil. Subject to further drilling and testing results, and partner and government approvals, a potential Phase 2 development could add an additional gross 30 mbbld facility. The Atrush-3 appraisal well, within the potential Phase 2 development area approximately four miles east of existing wells, confirmed the extension of the oil bearing reservoirs in 2013 and has been suspended as a potential future producer.
On the non-operated Sarsang block, the Swara Tika discovery was declared commercial in May 2014 and a field development plan was filed in June 2014. Currently, the East Swara Tika-1 exploration well is being sidetracked up-dip. Discussions are ongoing with the Ministry of Natural Resources to finalize the Swara Tika field development plan.
On the operated Harir block, we spud the Mirawa-2 appraisal well in December 2014 which is expected to reach total depth in the second quarter of 2015. In December 2014, we announced the Jisik-1 discovery and in 2013, the Mirawa-1 discovery. Both the Jisik-1 and Mirawa-1 exploratory wells had discovered multiple stacked oil and natural gas producing zones, and have been suspended for potential future use as producing wells.
Acquisitions and Dispositions
In the fourth quarter of 2014, we closed the sale of our Norway business, including the operated Alvheim FPSO, 10 operated licenses and a number of non-operated licenses on the Norwegian Continental Shelf in the North Sea, with an effective date of January 1, 2014 for proceeds of approximately $2.1 billion.
In the first quarter of 2014, we closed the sales of our 10 percent non-operated working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32 for aggregate proceeds of approximately $2 billion. See Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements for additional information about these dispositions, including discontinued operations presentation.

11


Productive and Drilling Wells
For our North America E&P and International E&P segments and discontinued operations combined, the following tables set forth gross and net productive wells and service wells as of December 31, 2014, 2013 and 2012 and drilling wells as of December 31, 2014.
 
Productive Wells(a)
 
 
 
 
 
 
 
 
 
Oil
 
Natural Gas
 
Service Wells  
 
Drilling Wells
  
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
7,058

 
2,919

 
2,246

 
1,023

 
2,638

 
760

 
45

 
25

E.G.

 

 
16

 
11

 
2

 
1

 

 

Other Africa
1,071

 
175

 
7

 
1

 
94

 
16

 
3

 
1

Total Africa
1,071

 
175

 
23

 
12

 
96

 
17

 
3

 
1

Other International
55

 
20

 
39

 
16

 
24

 
8

 
6

 
2

Total
8,184

 
3,114

 
2,308

 
1,051

 
2,758

 
785

 
54

 
28

2013

 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
6,632

 
2,568

 
2,763

 
1,482

 
2,349

 
744

 
 
 
 
E.G.

 

 
16

 
11

 
2

 
1

 
 
 
 
Other Africa
1,072

 
175

 
7

 
1

 
99

 
16

 
 
 
 
Total Africa
1,072

 
175

 
23

 
12

 
101

 
17

 
 
 
 
Other International
77

 
34

 
40

 
16

 
28

 
11

 
 
 
 
Total
7,781

 
2,777

 
2,826

 
1,510

 
2,478

 
772

 
 
 
 
2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
6,191

 
2,315

 
3,208

 
1,906

 
2,328

 
736

 
 
 
 
E.G.

 

 
14

 
9

 
4

 
3

 
 
 
 
Other Africa
1,050

 
171

 
6

 
1

 
101

 
16

 
 
 
 
Total Africa
1,050

 
171

 
20

 
10

 
105

 
19

 
 
 
 
Other International
77

 
34

 
40

 
16

 
28

 
11

 
 
 
 
Total
7,318

 
2,520

 
3,268

 
1,932

 
2,461

 
766

 
 
 
 
(a) 
Of the gross productive wells, wells with multiple completions operated by us totaled 31, 31 and 115 as of December 31, 2014, 2013 and 2012. Information on wells with multiple completions operated by others is unavailable to us.



12


Drilling Activity
For our North America E&P and International E&P segments and discontinued operations combined, the following table sets forth, by geographic area, the number of net productive and dry development and exploratory wells completed in each of the last three years.
 
Development
 
Exploratory
 
 
  
Oil
 
Natural
Gas
 
Dry
 
Total
 
Oil
 
Natural
Gas
 
Dry
 
Total
 
Total
Year Ended December 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
253

 
43

 
1

 
297

 
49

 
19

 
4

 
72

 
369

Africa
1

 

 

 
1

 

 

 
2

 
2

 
3

Other International
1

 

 

 
1

 

 

 

 

 
1

Total
255

 
43

 
1

 
299

 
49

 
19

 
6

 
74

 
373

Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
237

 
20

 

 
257

 
73

 
13

 
3

 
89

 
346

Africa
4

 

 

 
4

 
1

 

 
2

 
3

 
7

Other International

 

 

 

 

 

 
3

 
3

 
3

Total
241

 
20

 

 
261

 
74

 
13

 
8

 
95

 
356

Year Ended December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
U.S.
172

 
21

 
2

 
195

 
117

 
13

 
9

 
139

 
334

Africa
4

 

 

 
4

 
1

 

 

 
1

 
5

Other International
3

 

 

 
3

 

 

 

 

 
3

Total
179

 
21

 
2

 
202

 
118

 
13

 
9

 
140

 
342

Acreage
We believe we have satisfactory title to our North America E&P and International E&P properties in accordance with standards generally accepted in the industry; nevertheless, we can be involved in title disputes from time to time which may result in litigation. In the case of undeveloped properties, an investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. Our title to properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the industry. In addition, our interests may be subject to obligations or duties under applicable laws or burdens such as net profits interests, liens related to operating agreements, development obligations or capital commitments under international PSCs or exploration licenses.
The following table sets forth, by geographic area, the gross and net developed and undeveloped acreage held in our North America E&P and International E&P segments combined as of December 31, 2014.
 
Developed
 
Undeveloped
 
Developed and
Undeveloped
(In thousands)
Gross    
 
Net
 
Gross    
 
Net
 
Gross    
 
Net
U.S.
1,822

 
1,408

 
1,036

 
865

 
2,858

 
2,273

Canada

 

 
142

 
54

 
142

 
54

Total North America
1,822

 
1,408

 
1,178

 
919

 
3,000

 
2,327

E.G.
45

 
29

 
183

 
164

 
228

 
193

Other Africa
12,909

 
2,108

 
26,145

 
9,612

 
39,054

 
11,720

Total Africa
12,954

 
2,137

 
26,328

 
9,776

 
39,282

 
11,913

Other International
94

 
33

 
346

 
110

 
440

 
143

Total
14,870

 
3,578

 
27,852

 
10,805

 
42,722

 
14,383


13


In the ordinary course of business, based on our evaluations of certain geologic trends and prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future. If production is not established or we take no other action to extend the terms of the leases, licenses, or concessions, undeveloped acreage listed in the table below will expire over the next three years. We plan to continue the terms of many of these licenses and concession areas or retain leases through operational or administrative actions.
 
Net Undeveloped Acres Expiring
 
Year Ended December 31,
(In thousands)
2015
 
2016
 
2017
U.S.
211

 
150

 
94

E.G.
36

 

 

Other Africa
1,950

 
1,502

 
1,089

Total Africa
1,986

 
1,502

 
1,089

Other International
88

 

 

Total
2,285

 
1,652

 
1,183

Oil Sands Mining Segment
We hold a 20 percent non-operated interest in the AOSP, an oil sands mining and upgrading joint venture located in Alberta, Canada. The joint venture produces bitumen from oil sands deposits in the Athabasca region utilizing mining techniques and upgrades the bitumen to synthetic crude oils and vacuum gas oil.
The AOSP’s mining and extraction assets are located near Fort McMurray, Alberta, and include the Muskeg River and the Jackpine mines. Gross design capacity of the combined mines is 255,000 (51,000 net to our interest) barrels of bitumen per day. The AOSP operations use established processes to mine oil sands deposits from an open-pit mine, extract the bitumen and upgrade it into synthetic crude oils. Ore is mined using traditional truck and shovel mining techniques. The mined ore passes through primary crushers to reduce the ore chunks in size and is then sent to rotary breakers where the ore chunks are further reduced to smaller particles. The particles are combined with hot water to create slurry. The slurry moves through the extraction process where it separates into sand, clay and bitumen-rich froth. A solvent is added to the bitumen froth to separate out the remaining solids, water and heavy asphaltenes. The solvent washes the sand and produces clean bitumen that is required for the upgrader to run efficiently. The process yields a mixture of solvent and bitumen which is then transported from the mine to the Scotford upgrader via the approximately 300-mile Corridor Pipeline.
The AOSP's Scotford upgrader is located at Fort Saskatchewan, northeast of Edmonton, Alberta.  The bitumen is upgraded at Scotford using both hydrotreating and hydroconversion processes to remove sulfur and break the heavy bitumen molecules into lighter products. Blendstocks acquired from outside sources are utilized in the production of our saleable products. The upgrader produces synthetic crude oils and vacuum gas oil. The vacuum gas oil is sold to an affiliate of the operator under a long-term contract at market-related prices, and the other products are sold in the marketplace.
As of December 31, 2014, we own or have rights to participate in developed and undeveloped leases totaling approximately 163,000 gross (33,000 net) acres. The underlying developed leases are held for the duration of the project, with royalties payable to the province of Alberta. Synthetic crude oil sales volumes for 2014 averaged 50 mbbld and net-of-royalty production was 41 mbbld.
In December 2013, a Jackpine mine expansion project received conditional approval from the Canadian government. The project includes additional mining areas, associated processing facilities and infrastructure. The government conditions relate to wildlife, the environment and aboriginal health issues. We will evaluate the potential expansion project and government conditions after infrastructure reliability initiatives are completed.
The governments of Alberta and Canada have agreed to partially fund Quest CCS for $865 million Canadian.  In the third quarter of 2012, the Energy and Resources Conservation Board ("ERCB"), Alberta's primary energy regulator at that time, conditionally approved the project and the AOSP partners approved proceeding to construct and operate Quest CCS.   Government funding commenced in 2012 and continued as milestones were achieved during the development, construction and operating phases.  Failure of the AOSP to meet certain timing, performance and operating objectives may result in repaying some of the government funding.  Construction and commissioning of Quest CCS is expected to be completed by late 2015.

14


Reserves
Estimated Reserve Quantities
Reserves are disclosed by continent and by country if the proved reserves related to any geographic area, on an oil equivalent barrel basis, represent 15 percent or more of our total proved reserves. A geographic area can be an individual country, group of countries within a continent, or a continent. Other International ("Other Int’l"), includes the U.K. and the Kurdistan Region of Iraq. We closed the sale of our Angola assets in the first quarter of 2014 and our Norway business in the fourth quarter of 2014, and both are shown as discontinued operations ("Disc Ops") for all periods presented. Approximately 76 percent of our proved reserves are located in OECD countries.
Our December 31, 2014 proved reserves were calculated using the unweighted average of closing prices for the first day of each month in 2014 within the 12-month period. The 2014 unweighted averages for certain of the benchmark prices were as follows:
WTI crude oil - $94.99 per bbl
Henry Hub natural gas - $4.31 per mmbtu
Brent crude oil - $101.39 per bbl
When determining the December 31, 2014 proved reserves for each property, the benchmark prices listed above were adjusted with price differentials that account for property-specific quality and location differences. Beginning in the second half of 2014, the crude oil benchmarks began to decline and this decline continued into early 2015. In addition, the Henry Hub natural gas benchmark began to decline in late 2014 and continued its decline into 2015. Commodity prices are likely to remain volatile based on global supply and demand and could decline further. The January 2015 benchmark closing prices for the first day of the month were WTI crude oil of $52.69 per bbl, Henry Hub natural gas of $2.99 per mmbtu and Brent crude oil of $55.55 per bbl. Sustained reduced commodity prices could have a material effect on the quantity and future cash flows of our proved reserves. To the extent that we experience a sustained period of reduced commodity prices in 2015, there is a risk that a portion of our proved reserves could be deemed uneconomic and no longer be classified as proved. Estimates of future cash flows associated with proved reserves are based on actual costs of developing and producing the reserves as of the end of the year. The decline in commodity prices experienced in the second half of 2014 has resulted in a reduction in the costs of developing and producing reserves. The impact of sustained reduced commodity prices on future cash flows will be partially offset by the impact of lower costs.
A sustained period of lower commodity prices could also cause us to decrease our near term capital programs and defer investment until prices improve. A shifting of capital expenditures into future periods outside of five years from the initial proved reserve booking could potentially lead to a reduction in proved undeveloped reserves. See Item 1A. Risk Factors for a further discussion of how a substantial extended decline in commodity prices could impact us.
The most significant increase in total proved reserves from 2013 to 2014 related to our U.S. unconventional shale plays, while sales of reserves in place related to our Norway and Angola discontinued operations were the largest decreases in 2014 proved reserves.  Excluding discontinued operations, total proved reserves related to continuing operations increased 133 mmboe primarily due to drilling programs in our U.S. unconventional shale plays and additions in E.G. and the Kurdistan Region of Iraq, offset by production.  In the U.S., we added 288 mmboe in 2014, excluding purchases and sales of reserves in place and production, amounting to an increase of 37 percent over the 2013 ending balance, mainly due to downspacing, drilling activity and improved well performance.  The negative 55 mmboe revision to Canadian synthetic crude oil reserves primarily reflects the impact of technical and price changes on calculated royalty volumes as well as development plan changes in the mineable areas. See Item 8. Financial Statements and Supplementary Data - Supplementary Information on Oil and Gas Producing Activities for more information.
The following tables set forth estimated quantities of our proved crude oil and condensate, NGL, natural gas and synthetic crude oil reserves based upon an unweighted average of closing prices for the first day of each month in the 12-month periods ended December 31, 2014, 2013 and 2012.


15


 
North America
 
Africa
 
 
 
 
 
 
 
 
December 31, 2014
  U.S. 
 
Canada
 
Total  
 
E.G.  
 
Other
 
Total    
 
Other Int'l
 
Cont Ops
 
Disc Ops
 
Total
Proved Developed Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and condensate (mmbbl)
294

 

 
294

 
30

 
175

 
205

 
19

 
518

 

 
518

Natural gas liquids (mmbbl)
68

 

 
68

 
15

 

 
15

 

 
83

 

 
83

Natural gas (bcf)
575

 

 
575

 
664

 
94

 
758

 
17

 
1,350

 

 
1,350

Synthetic crude oil (mmbbl)

 
644

 
644

 

 

 

 

 
644

 

 
644

Total proved developed reserves  (mmboe)
458

 
644

 
1,102

 
155

 
191

 
346


22

 
1,470

 


1,470

Proved Undeveloped Reserves
 
 
 
 
 
 
 
 
 
 
 
 

 

 
 
 

Crude oil and condensate (mmbbl)
340

 

 
340

 
27

 
33

 
60

 
10

 
410

 

 
410

Natural gas liquids (mmbbl)
93

 

 
93

 
15

 

 
15

 
1

 
109

 

 
109

Natural gas (bcf)
569

 

 
569

 
541

 
115

 
656

 
5

 
1,230

 

 
1,230

Synthetic crude oil (mmbbl)

 
4

 
4

 

 

 

 

 
4

 

 
4

Total proved undeveloped reserves  (mmboe)
528

 
4

 
532

 
133

 
52

 
185

 
11

 
728

 

 
728

Total Proved Reserves
 
 
 
 
 
 
 
 
 
 
 
 

 

 
 
 

Crude oil and condensate (mmbbl)
634

 

 
634

 
57

 
208

 
265

 
29

 
928

 

 
928

Natural gas liquids (mmbbl)
161

 

 
161

 
30

 

 
30

 
1

 
192

 

 
192

Natural gas (bcf)
1,144

 

 
1,144

 
1,205

 
209

 
1,414

 
22

 
2,580

 

 
2,580

Synthetic crude oil (mmbbl)

 
648

 
648

 

 

 

 

 
648

 

 
648

Total proved reserves (mmboe)
986

 
648

 
1,634

 
288

 
243

 
531

 
33

 
2,198

 

 
2,198

 
North America
 
Africa
 
 
 
 
 
 
 
 
December 31, 2013
  U.S. 
 
Canada
 
Total  
 
E.G.  
 
Other
 
Total    
 
Other Int'l
 
Cont Ops
 
Disc Ops
 
Total
Proved Developed Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and condensate (mmbbl)
241

 

 
241

 
37

 
176

 
213

 
19

 
473

 
77

 
550

Natural gas liquids (mmbbl)
51

 

 
51

 
18

 

 
18

 
1

 
70

 

 
70

Natural gas (bcf)
540

 

 
540

 
823

 
95

 
918

 
21

 
1,479

 
20

 
1,499

Synthetic crude oil (mmbbl)

 
674

 
674

 

 

 

 

 
674

 

 
674

Total proved developed reserves (mmboe)
382

 
674

 
1,056

 
193

 
192

 
385

 
23

 
1,464

 
80

 
1,544

Proved Undeveloped Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and condensate (mmbbl)
256

 

 
256

 
27

 
39

 
66

 
6

 
328

 
14

 
342

Natural gas liquids (mmbbl)
68

 

 
68

 
16

 

 
16

 

 
84

 

 
84

Natural gas (bcf)
485

 

 
485

 
497

 
110

 
607

 
7

 
1,099

 
73

 
1,172

Synthetic crude oil (mmbbl)

 
6

 
6

 

 

 

 

 
6

 

 
6

Total proved undeveloped reserves (mmboe)
405

 
6

 
411

 
125

 
57

 
182

 
8

 
601

 
26

 
627

Total Proved Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and condensate (mmbbl)
497

 

 
497

 
64

 
215

 
279

 
25

 
801

 
91

 
892

Natural gas liquids (mmbbl)
119

 

 
119

 
34

 

 
34

 
1

 
154

 

 
154

Natural gas (bcf)
1,025

 

 
1,025

 
1,320

 
205

 
1,525

 
28

 
2,578

 
93

 
2,671

Synthetic crude oil (mmbbl)


680

 
680



 

 



 
680

 


680

Total proved reserves (mmboe)
787

 
680

 
1,467

 
318

 
249

 
567

 
31

 
2,065

 
106

 
2,171


16


 
North America
 
Africa
 
 
 
 
 
 
 
 
December 31, 2012
  U.S. 
 
Canada
 
Total  
 
E.G.  
 
Other
 
Total    
 
Other Int'l
 
Cont Ops
 
Disc Ops
 
Total
Proved Developed Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and condensate (mmbbl)
169

 

 
169

 
45

 
168

 
213

 
20

 
402

 
63

 
465

Natural gas liquids (mmbbl)
29

 

 
29

 
23

 

 
23

 
1

 
53

 

 
53

Natural gas (bcf)
546

 

 
546

 
980

 
99

 
1,079

 
8

 
1,633

 
20

 
1,653

Synthetic crude oil (mmbbl)

 
653

 
653

 

 

 

 

 
653

 

 
653

Total proved developed reserves (mmboe)
289

 
653

 
942

 
231

 
185

 
416

 
22

 
1,380

 
66

 
1,446

Proved Undeveloped Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and condensate (mmbbl)
218

 

 
218

 
27

 
41

 
68

 
4

 
290

 
19

 
309

Natural gas liquids (mmbbl)
59

 

 
59

 
15

 

 
15

 

 
74

 

 
74

Natural gas (bcf)
497

 

 
497

 
444

 
110

 
554

 
6

 
1,057

 
69

 
1,126

Synthetic crude oil (mmbbl)

 

 

 

 

 

 

 

 

 

Total proved undeveloped reserves (mmboe)
360

 

 
360

 
116

 
59

 
175

 
5

 
540

 
31

 
571

Total Proved Reserves
 
 
 
 
 


 
 
 
 
 
 
 


Crude oil and condensate (mmbbl)
387

 

 
387

 
72

 
209

 
281

 
24

 
692

 
82

 
774

Natural gas liquids (mmbbl)
88

 

 
88

 
38

 

 
38

 
1

 
127

 

 
127

Natural gas (bcf)
1,043

 

 
1,043

 
1,424

 
209

 
1,633

 
14

 
2,690

 
89

 
2,779

Synthetic crude oil (mmbbl)

 
653

 
653

 

 

 

 

 
653

 

 
653

Total proved reserves (mmboe)
649

 
653

 
1,302

 
347

 
244

 
591

 
27

 
1,920

 
97

 
2,017

Preparation of Reserve Estimates
All estimates of reserves are made in compliance with SEC Rule 4-10 of Regulation S-X. Crude oil and condensate, NGL, natural gas and synthetic crude oil reserve estimates are reviewed and approved by our Corporate Reserves Group, which includes our Director of Corporate Reserves and his staff of Reserve Coordinators. Crude oil and condensate, NGL, and natural gas reserve estimates are developed or reviewed by Qualified Reserves Estimators ("QREs"). QREs are engineers or geoscientists who hold at least a Bachelor of Science degree in the appropriate technical field, have a minimum of three years of industry experience with at least one year in reserve estimation and have completed Marathon Oil's QRE training course. Our Corporate Reserves group screens all fields with net proved reserves of 20 mmboe or greater, every year, to determine if a field review will be performed. Any change to proved reserve estimates in excess of 1 mmboe on a total field basis, within a single month, must be approved by a Reserve Coordinator.
Our Director of Corporate Reserves, who reports to our Vice President, Operations Services, has a Bachelor of Science degree in petroleum engineering and is a registered Professional Engineer in the State of Texas. In his 27 years with Marathon Oil, he has held numerous engineering and management positions, including managing our OSM segment. He is a member of the Society of Petroleum Engineers ("SPE") and a former member of the Petroleum Engineering Advisory Council for the University of Texas at Austin.
Estimates of synthetic crude oil reserves are prepared by GLJ Petroleum Consultants ("GLJ") of Calgary, Canada, third-party consultants. Their reports for all years are filed as exhibits to this Annual Report on Form 10-K. The individual responsible for the estimates of our synthetic crude oil reserves has 14 years of experience in petroleum engineering, has conducted surface mineable oil sands evaluations since 2009 and is a registered Practicing Professional Engineer in the Province of Alberta.
Audits of Estimates
Third-party consultants are engaged to provide independent estimates for fields that comprise 80 percent of our total proved reserves over a rolling four-year period for the purpose of auditing and validating our internal reserve estimates. We exceeded this percentage for the four-year period ended December 31, 2014. We have established a tolerance level of 10 percent such that initial estimates by the third-party consultants for each field are accepted if they are within 10 percent of our internal estimates. Should the third-party consultants’ initial analysis fail to reach our tolerance level, both parties re-examine the information provided, request additional data and refine their analysis, if appropriate. This resolution process is continued until both estimates are within 10 percent. In the very limited instances where differences outside the 10 percent tolerance cannot be resolved by year end, a plan to resolve the difference is developed and senior management consent is obtained. The audit process did not result in any significant changes to our reserve estimates for 2014, 2013 or 2012.

17


During 2014, 2013 and 2012, Netherland, Sewell & Associates, Inc. ("NSAI") prepared a certification of the prior year's reserves for the Alba field in E.G. The NSAI summary reports are filed as an exhibit to this Annual Report on Form 10-K. Members of the NSAI team have multiple years of industry experience, having worked for large, international oil and gas companies before joining NSAI. The senior technical advisor has over 35 years of practical experience in petroleum geosciences, with over 15 years experience in the estimation and evaluation of reserves. The second team member has over 10 years of practical experience in petroleum engineering, with 5 years experience in the estimation and evaluation of reserves. Both are registered Professional Engineers in the State of Texas.
Ryder Scott Company ("Ryder Scott") also performed audits of the prior years' reserves of several of our fields in 2014, 2013 and 2012. Their summary reports are filed as exhibits to this Annual Report on Form 10-K. The team lead for Ryder Scott has over 20 years of industry experience, having worked for a major international oil and gas company before joining Ryder Scott. He is a member of SPE, where he served on the Oil and Gas Reserves Committee, and is a registered Professional Engineer in the State of Texas.
Changes in Proved Undeveloped Reserves
As of December 31, 2014, 728 mmboe of proved undeveloped reserves were reported, an increase of 101 mmboe from December 31, 2013. The following table shows changes in total proved undeveloped reserves for 2014:
(mmboe)
 
Beginning of year
627

Revisions of previous estimates
1

Improved recovery
1

Purchases of reserves in place
4

Extensions, discoveries, and other additions
227

Dispositions
(29
)
Transfers to proved developed
(103
)
End of year
728

Significant additions to proved undeveloped reserves during 2014 included 121 mmboe in the Eagle Ford and 61 mmboe in the Bakken shale plays due to development drilling. Transfers from proved undeveloped to proved developed reserves included 67 mmboe in the Eagle Ford, 26 mmboe in the Bakken and 1 mmboe in the Oklahoma Resource Basins due to development drilling and completions. Costs incurred in 2014, 2013 and 2012 relating to the development of proved undeveloped reserves, were $3,149 million, $2,536 million and $1,995 million.
A total of 102 mmboe was booked as extensions, discoveries or other additions due to the application of reliable technology. Technologies included statistical analysis of production performance, decline curve analysis, pressure and rate transient analysis, reservoir simulation and volumetric analysis. The statistical nature of production performance coupled with highly certain reservoir continuity or quality within the reliable technology areas and sufficient proved undeveloped locations establish the reasonable certainty criteria required for booking proved reserves.
Projects can remain in proved undeveloped reserves for extended periods in certain situations such as large development projects which take more than five years to complete, or the timing of when additional gas compression is needed. Of the 728 mmboe of proved undeveloped reserves at December 31, 2014, 19 percent of the volume is associated with projects that have been included in proved reserves for more than five years. The majority of this volume is related to a compression project in E.G. that was sanctioned by our Board of Directors in 2004. The timing of the installation of compression is being driven by the reservoir performance with this project intended to maintain maximum production levels. Performance of this field since the Board sanctioned the project has far exceeded expectations. Estimates of initial dry gas in place increased by roughly 10 percent between 2004 and 2010. During 2012, the compression project received the approval of the E.G. government, allowing design and planning work to progress towards implementation, with completion expected by mid-2016. The other component of Alba proved undeveloped reserves is an infill well approved in 2013 and to be drilled in the second quarter of 2015.
Proved undeveloped reserves for the North Gialo development, located in the Libyan Sahara desert, were booked for the first time in 2010. This development, which is anticipated to take more than five years to develop, is executed by the operator and encompasses a multi-year drilling program including the design, fabrication and installation of extensive liquid handling and gas recycling facilities. Anecdotal evidence from similar development projects in the region lead to an expected project execution time frame of more than five years from the time the reserves were initially booked. Interruptions associated with the civil unrest in 2011 and third-party labor strikes and civil unrest in 2013-2014 have also extended the project duration.
As of December 31, 2014, future development costs estimated to be required for the development of proved undeveloped crude oil and condensate, NGLs, natural gas and synthetic crude oil reserves related to continuing operations for the years 2015 through 2019 are projected to be $2,915 million, $2,598 million, $2,493 million, $2,669 million and $2,745 million.

18


Net Production Sold
 
North America
 
Africa
 

 
 
 
 
  
  U.S. 
 
Canada
 
Total  
 
E.G.  
 
Other
 
Total    
 
Other Int'l
 
Disc Ops
 

Total
Year Ended December 31,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude and condensate (mbbld)(a)
157

 

 
157

 
21

 
7

 
28

 
11

 
48

 
244

Natural gas liquids (mbbld)
29

 

 
29

 
10

 

 
10

 

 

 
39

Natural gas (mmcfd)(b)
310

 

 
310

 
439

 
1

 
440

 
21

 
37

 
808

Synthetic crude oil (mbbld)(c)

 
41

 
41

 

 

 

 

 

 
41

Total production sold (mboed)
238

 
41

 
279

 
104

 
7

 
111

 
15

 
54

 
459

2013
 
 
 

 
 
 
 
 

 
 
 
 
 

Crude and condensate (mbbld)(a)
126

 

 
126

 
23

 
24

 
47

 
14

 
81

 
268

Natural gas liquids (mbbld)
23

 

 
23

 
11

 

 
11

 
1

 

 
35

Natural gas (mmcfd)(b)
312

 

 
312

 
442

 
22

 
464

 
25

 
51

 
852

Synthetic crude oil (mbbld)(c)

 
42

 
42

 

 

 

 

 

 
42

Total production sold (mboed)
201

 
42

 
243

 
107

 
27

 
134

 
20

 
89

 
486

2012
 
 
 

 
 
 
 
 

 
 
 
 
 

Crude and condensate (mbbld)(a)
96

 

 
96

 
25

 
42

 
67

 
15

 
81

 
259

Natural gas liquids (mbbld)
11

 

 
11

 
11

 

 
11

 
1

 

 
23

Natural gas (mmcfd)(b)(d)
358

 

 
358

 
428

 
15

 
443

 
33

 
53

 
887

Synthetic crude oil (mbbld)(c)

 
41

 
41

 

 

 

 

 

 
41

Total production sold (mboed)
166

 
41

 
207

 
108

 
44

 
152

 
21

 
90

 
470

(a) 
The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.
(b) 
Excludes volumes acquired from third parties for injection and subsequent resale.
(c) 
Upgraded bitumen excluding blendstocks.
(d) 
U.S. natural gas volumes exclude volumes produced in Alaska that were stored for later sale in response to seasonal demand, although our reserves had been reduced by those volumes.
Average Sales Price per Unit
 
North America
 
Africa
 

 
 
 
 
(Dollars per unit)
  U.S. 
 
Canada
 
Total  
 
E.G.  
 
Other
 
Total    
 
Other Int'l
 
Disc Ops
 

Total
2014
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude and condensate (bbl)
$
85.25

 
$

 
$
85.25

 
$
81.01

 
$
94.70

 
$
84.48

 
$
94.31

 
$
109.80

 
$
90.37

Natural gas liquids (bbl)
33.42

 

 
33.42

 
1.00

(a) 

 
1.00

 
67.73

 

 
25.25

Natural gas (mcf)
4.57

 

 
4.57

 
0.24

(a) 
3.11

 
0.25

 
8.27

 
9.94

 
2.55

Synthetic crude oil (bbl)

 
83.35

 
83.35

 

 

 

 

 

 
83.35

2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude and condensate (bbl)
$
94.19

 
$

 
$
94.19

 
$
90.62

 
$
122.92

 
$
107.31

 
$
110.76

 
$
112.36

 
$
102.81

Natural gas liquids (bbl)
35.12

 

 
35.12

 
1.00

(a) 

 
1.00

 
72.14

 

 
24.78

Natural gas (mcf)
3.84

 

 
3.84

 
0.24

(a) 
5.44

 
0.49

 
10.64

 
13.01

 
2.75

Synthetic crude oil (bbl)

 
87.51

 
87.51

 

 

 

 

 

 
87.51

2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crude and condensate (bbl)
$
91.30

 
$

 
$
91.30

 
$
92.56

 
$
127.31

 
$
114.52

 
$
109.50

 
$
116.70

 
$
106.35

Natural gas liquids (bbl)
39.57

 

 
39.57

 
1.00

(a) 

 
1.00

 
78.81